Image by Stormotion.io, used under a Creative Commons license. 

This is the sixth in an occasional series from AEE published in Utility Dive that addresses how the power sector can successfully transition to a 21st Century Electricity System.

Throughout the economy, businesses rely heavily on services to fulfill their needs. In the utility sector, however, the use of services has taken hold more slowly, especially when those services reduce the need for capital investment in their systems. At the heart of the matter is the way utilities recover costs and generate earnings. At stake is faster adoption of modern technology, better service, a more efficient system, and lower costs for customers.

As the nation’s top per capita manufacturing state – the No. 1 steel producer and No. 3 for cars – Indiana is an energy-intensive state, so saving energy means saving money here as much as anywhere. But cost is driven especially by turning on those last, most expensive power plants – or building new ones – to meet demand at its peak. Meeting peak demand is expensive; not only are wholesale electricity prices higher during those times, but about 10% of our state’s electric power infrastructure investments focus on serving load during just 1% of the hours of the year. If Indiana can shave or eliminate these expensive peaks it could reduce costs and improve reliability, because times of peak demand are also typically when the grid is most stressed. Our new report shows three ways that Indiana can reduce peak demand.

Cybersecurity is a growing issue for the U.S. economy, especially for the critical infrastructure that keeps the nation’s energy system operating — the interconnected and interdependent systems of natural gas, water, communications, and fuel distribution, and especially the highly dynamic electric power sector, which is seeing the widespread introduction of advanced and intelligent energy technologies. But that doesn’t mean the intelligent and distributed grid of the future need be more vulnerable to cyberattack than the closed and centralized electric power system it is in the process of replacing.

Back in July, Advanced Energy Economy published a list of the top utility regulation trends of 2017 – so far. With 2017 almost in the rearview mirror, we check in on the top public utility commission actions of the year. Not surprisingly, the challenges PUCs are grappling with are wide-ranging and diverse: utility business model reforms, distribution system planning, grid modernization, rate design changes, large investments in renewables, transportation electrification, energy storage, wholesale market changes, and data access, to name a few. Here is a roundup of the top 10 matters before PUCs in 2017.

The digital revolution, which has transformed so many other industries, is now taking hold in the electric power sector. This is happening at the same time as increasing deployment of distributed energy resources (DER), including energy efficiency, demand management, distributed generation, energy storage, and electric vehicles. New technologies, the use of “big data,” apps, and the “grid of things” are leading to a greater variety of services and interactions between utilities, customers and third parties (non-utility companies that offer energy products and services).

One way to slice and dice this increasingly complex marketplace is whether services are considered “basic” or “value-added.” This is the subject of a new report from Lawrence Berkeley National Lab, Value-Added Electricity Services: New Roles for Utilities and Third-Party Providers, in which AEE was the author of one of three perspectives on emerging roles for utilities and third parties in providing value-added services.